Petronas looks at project cost, market uncertainty in LNG decision
(The Independent; Singapore; Feb. 22) - Malaysia’s Petronas has voiced its concerns over the global oversupply of liquefied natural gas, putting in question whether it will move forward with its multibillion-dollar LNG project on the British Colombia’s Pacific Coast. CEO Wan Zulkiflee Wan Ariffin sounded the company’s uncertainty when he said Petronas is looking at the cost structure, plant size, technologies and LNG global demand forecasts, not knowing whether it has sufficient orders for the plant’s output.
Local business dailies in Malaysia reported the CEO has said the company is reviewing its strategy for the project, including how to further reduce costs and whether “we have ready demand for the LNG.” An overall review — not just selected components — will determine the fate of the project near Prince Rupert, B.C. He also pointed to a tepid market, oversupply and tight spending by oil and gas companies, adding that worries of over-production and low demand continue to influence decisions on LNG investments.
The company is in consultation with its partners in the project: China Petrochemical Corp., Japan Petroleum Exploration Co., Indian Oil Corp. and Brunei National Petroleum Co. The project, Pacific NorthWest LNG, has its government approvals, though it is still working with local First Nations to resolve a dispute over the project’s marine dock location in sensitive salmon habitat. An investment decision is expected later this year. The project could produce close to 20 million tonnes of LNG per year.
Not everyone as optimistic as Shell of LNG demand
(The Telegraph; UK; Feb. 20) - Shell has brushed off concern that the burgeoning global market for liquefied natural gas is oversupplied, after paying nearly $50 billion last year to buy market leader BG Group. Shell’s first outlook report for LNG since the tie-up was finalized predicts a market boom as global demand from countries including China and India will outpace new supplies from export project start-ups.
The market for LNG has already grown considerably in recent years, but analysts have raised fears that an explosion of new projects might flood the market. A deluge of LNG could push down prices just as Shell works to pay down the heavy cost of its tie-up with BG. Ed Cox, an LNG analyst at market intelligence provider ICIS, confirmed that demand for LNG is growing, but cautioned that the full impact of the coming supply surge may only take effect toward the end of the decade.
“Part of the reason the LNG market was not oversupplied last year was because start-up of new production — notably from Australia — was delayed. Operating rates at some other plants in Africa, the Middle East and the Americas were reduced due to technical or feedstock issues,” Cox said. He added that some buyers have flocked to the market to take advantage of low prices but their interest could wane once prices begin to rise. A more buoyant market could also prompt extra supply from U.S. shale gas producers.
Japan plans second round of methane hydrate production testing
(Platts; Feb. 20) - Japan plans to conduct a second testing for offshore production of methane hydrate starting late April, aiming to run the tests non-stop for up to a month, an official at the Ministry of Economy, Trade and Industry said Feb. 20. This will be the world's second offshore methane hydrate production test after Japan produced about 700,000 cubic feet of gas a day in a six-day test in the Pacific in March 2013. That trial followed more than a decade of field research and testing of various technologies.
Key objectives for the test are to evaluate whether Japan can steadily produce gas from methane hydrate using the decreasing-pressure system for a given period, with a view to commercializing output in the future, the official said. State-owned Japan Oil, Gas and Metals National Corp. is leading the test. Operator Japan Methane Hydrate Operating Co. will extend its two production wells that have already been drilled by a further 50 to 60 meters to reach methane hydrate layers about 300 meters below the seabed at a water depth of about 1,000 meters, the official said. Japan Methane Hydrate was formed in October 2014 as a joint-venture of 11 Japanese companies.
Australia LNG plant operator sees growth potential as processing hub
(MarketWatch; Feb. 21) – Australia’s Woodside Petroleum is positioning to boost its gas export capacity in the coming years in expectation that still-rising supplies of liquefied natural gas will be absorbed by higher Asian demand. The company said Feb. 21 it is planning to increase production at its Pluto LNG plant in Western Australia and could position the plant, which opened in 2012, as a hub for undeveloped gas fields nearby.
Woodside CEO Peter Coleman said the mid- to longer-term demand outlook for LNG remains strong and new markets are being established. Global supply now outstrips demand, after multibillion-dollar investments in new facilities in Australia and as the U.S. begins exporting, yet Coleman said demand continues to grow. Woodside intends to tap existing gas supplies around its Pluto operation to lift output. It also will consider adding a smaller-scale production line at the facility.
Coleman said it was unlikely there would be large single buyers of LNG in the next few years that would commit to new supplies and underpin big LNG developments, but there remains scope for smaller-scale developments and for existing operations to collaborate to lower costs by sharing facilities, supplies and maintenance.
Louisiana appeals court rejects property tax deal for LNG project
(KATC; Louisiana; Feb. 21) - A deal that would have allowed a liquefied natural gas export project developer to pay Louisiana’s Cameron Parish a negotiated amount instead of value-based property taxes has been rejected by a state appeals court. In an opinion released Feb. 20, a three-judge panel upheld an earlier ruling by a state district judge that the parish council agreement with Cameron LNG exceeded its authority.
Although the "agreement does not exempt taxes, it operates as a partial exemption of a manufacturer’s taxes for 23 years … for which there is no precedent and in a manner that is constitutionally prohibited," the appeals court said. Cameron LNG is constructing an LNG production and export facility in Hackberry, La., where the partners, led by Sempra, have operated an LNG import terminal since 2009. The $10 billion export project is scheduled for a 2018 start-up.
The parish council had crafted an agreement with Cameron LNG to accept fixed annual payments in lieu of traditional property taxes based on the facility's assessed value. The deal called for payments of $4.5 million a year from 2016 to 2018 and $24.5 million a year 2019-2038. But the parish assessor and taxpayers sued, arguing Cameron would pay less than half the cost of property taxes. The court ruled that local governments can sign agreements with developers, but this one violated a state constitution provision that prohibits such deals from extending beyond five years with a five-year renewal.
B.C. will pay First Nations even if LNG project does not proceed
(Times Colonist columnist; Victoria, BC; Feb. 21) - A lot of entities and individuals operate on the assumption that the liquefied natural gas vision for British Columbia is dormant or defunct. But one of the remaining true believers is the B.C. government. It was on full display last week at a signing ceremony that brought two First Nations on board with the Petronas-sponsored Pacific NorthWest LNG proposal at Prince Rupert.
The Lax Kw’alaams First Nation signed an agreement that appears very lucrative. The government costs it out at $98.5 million. It includes $22 million from a trust contribution, $7 million of which will arrive the day the project makes an investment decision. The rest is to be released once construction begins. The band would get an annual benefit of $590,000 and an ongoing share of production benefits, along with benefits from the pipeline. There is also a $50 million provincial commitment for roads and transportation.
A similar deal was signed with another First Nation in the region, the Metlakatla. It’s worth $46 million, with $5 million payable from the government immediately, regardless of progress with the LNG project. Funds are earmarked for shellfish aquaculture and up to $17.5 million for a senior care facility. The province is putting up the cash, not the company. They look like attractive deals for the First Nations. If the project doesn’t go, some of the benefits will flow regardless. The province continues to believe.
Chevron makes plans for potential shale gas play in Alberta
(Calgary Herald; Feb. 16) - Pembina Pipeline Corp. has reached an agreement with Chevron Canada to build natural gas pipelines and processing facilities for a potential gas production operation northwest of Edmonton. The Calgary-based pipeline company said its 20-year deal with Chevron involves construction and operation of potential gas and liquids infrastructure in the Duvernay shale resource play near Fox Creek, Alberta.
Pembina said it could ultimately spend billions of dollars on the project, which has not been sanctioned by Chevron or received regulatory approvals. Chevron has been conducting an appraisal of its Duvernay holdings in the Fox Creek area since mid-2014, using two drilling rigs to evaluate well production rates and reservoir performance. The company holds a 70 percent interest in 330,000 acres in the gas play, having sold 30 percent to the Canadian subsidiary of Kuwait Foreign Petroleum Exploration Co.
The deal with Pembina requires the company to build and run gas gathering pipelines and processing facilities, liquids facilities and other infrastructure, should Chevron sanction a project and secure regulatory approvals. Chevron said it remains focused on its appraisal program and could not provide a timeline for a decision on production.
Tanzania’s problems could raise cost for debt, including LNG project
(Bloomberg; Feb. 16) - For investors considering financing Tanzania’s proposed $12.3 billion borrowing program, the government’s handling of its power utility’s debt problems may give pause for thought. Last month, President John Magufuli fired the Tanzania Electric Supply Co.’s (Tanesco) chief executive officer and vetoed the company’s decision to raise electricity prices, ignoring International Monetary Fund advice that higher rates could help improve the company’s financial position.
The state is also facing arbitration over its failure to pay more than $35 million owed for power from a gas-fired plant built by a U.S. company. “The current state of Tanesco is a cautionary tale of how state-owned enterprises in Tanzania are managed, particularly with respect to debt,” said Ahmed Salim, a vice president at Teneo Strategy, a Dubai-based research group. “In order for Tanzania to secure a good credit rating, institutions like Tanesco have to have the opportunity to reform, even if it means raising tariffs.”
The nation with East Africa’s largest deposits of natural gas after Mozambique plans to spend close to $50 billion over the next five years on projects including a liquefied natural gas export plant, rail links, and an industrial zone around a planned port. Tanesco’s travails could increase the premium at which Tanzania enters the Eurobond market and weigh on any credit ratings, said Lisa Brown, an analyst at Rand Merchant Bank, a unit of Johannesburg-based FirstRand.
Battle grows in Australia as LNG exports drive local gas prices higher
(Australian Broadcasting Corp.; Feb. 19) - As the closure of the Hazelwood coal-fired power station in Victoria next month approaches, debate around Australia's energy security is intensifying, especially after the recent power blackouts and price spikes in South Australia and Queensland. Early this month, Prime Minister Malcolm Turnbull said increasing the gas supply was "vital for our energy future.” It’s complicated by the fact that much of the country’s reserves leave the country as liquefied natural gas.
Almost $200 billion invested in LNG export projects had unintended consequences. "It connected Australia's gas market, which had been very low price, to the international market, where those high Asian prices meant that consumers in Asia were prepared to pay more for our gas," said Tony Wood, the Grattan Institute's energy program director. "That meant inevitably that the domestic gas price was going to rise ... of the order of twice as much as domestic gas consumers had been paying,” he said.
After last year's blackout in South Australia, the federal government sought a review, with the preliminary report warning: "Additional gas supply is urgently needed, but the domestic supply is constrained by international LNG demand, state and territory moratoria, low rates of exploration and pipeline capacity shortages. This is adding to price pressures." Calls are growing for a portion of Australia's East Coast gas to be set aside or reserved for domestic use. But the government opposes the idea, as does the gas industry — instead calling for an end to state limits on coal-seam gas exploration.
Royalty dispute continues between villagers and Papua New Guinea
(Australian Broadcasting Corp.; Feb. 20) - Villagers in Papua New Guinea are protesting at the country's biggest resources project because the government has not paid them long overdue royalties. Hundreds of people who live near the PNG liquefied natural gas plant outside Port Moresby have gathered around the main gate in an attempt to block access. ExxonMobil, the operator of Papua New Guinea LNG, issued a statement saying the protest had not affected operations at the plant.
The government has yet to pay royalties from the $20 billion project because of disputes over identifying landowners of the gas fields and pipeline right-of-way in the country's highlands. An attempt at alternative dispute resolution has stalled and the matter is in court. But a spokesman for the Port Moresby landowners, Chief Nao Nao, said that should not stop the government from paying people verified as landowners. “The people are very frustrated today," he said.
This is the second major protest affecting the LNG project. Landowners from the gas fields in Hela Province blockaded the entrance to the conditioning plant at Hides in August 2016 over non-payment of royalties and fears they would miss out on promised equity in the project. The country’s Minister for Petroleum and Energy said payment of the disputed land royalties was expected by the end of March if a process to formally recognize landowners from the plant site can be concluded.
Research finds more spills at fractured well sites
(BBC News; Feb. 21) - Up to 16 percent of hydraulically fractured oil and gas wells spill liquids every year, according to new research from U.S. scientists. They found that there had been 6,600 releases from fracked wells over a 10-year period in four states. The biggest problems were reported in North Dakota, where 67 percent of the spills were recorded. The largest spill recorded was about 630 barrels of fluid.
A study carried out by the Environment Protection Agency on fracking in eight states between 2006 and 2012 concluded that 457 spills had occurred. But this new study, while limited to just four states with adequate data, suggests the level of spills is much higher. The researchers found 6,648 spills between 2005 and 2014. "The EPA just looked at spills from the hydraulic fracturing process itself, which is just a few days to a few weeks," lead author Lauren Patterson from Duke University told BBC News.
"We're looking at spills at unconventional wells from the time of the drilling through production, which could be decades,” Patterson said. The state reporting the highest number was North Dakota, a hot bed of activity in oil and gas. The data recorded 4,453 spills in the state, much higher than Pennsylvania, Colorado and New Mexico. This can be explained by reporting requirements. In North Dakota, any spill over 42 gallons has to be reported, while in Colorado and New Mexico the requirement was 210 gallons.
Goldman forecasts U.S. crude $55 - $57.50 this year
(Reuters; Feb. 22) - Goldman Sachs expects global crude oil inventories to keep falling due to production cuts and strong growth in demand, although stockpiles are likely to rise in the United States. "We do not view the recent U.S. builds as derailing our forecast for a gradual draw in inventories, with in fact the rest of the world already showing signs of tightness," analysts at the bank said in a note dated Feb. 21.
The Wall Street bank reiterated its forecast for Brent and U.S. crude prices rising to $59 and $57.50 per barrel, respectively, in the second quarter, before dropping to $57 and $55 for the rest of 2017. Surging U.S. output has pushed crude and gasoline inventories to record highs, keeping a lid on prices after they climbed following an agreement by the Organization of the Petroleum Exporting Countries and other producers to cut output by about 1.8 million barrels per day.
"While the production cuts have so far reached a historically high level of compliance at 90 percent, the rebound in U.S. drilling activity has exceeded even our above-consensus expectations," Goldman said. However, the increase in U.S. drilling points to factors including further improvement in shale productivity and funding for the industry, rather than expectations of an increase in prices, the bank said.
TransCanada goes to open season on gas mainline tariff
(Globe and Mail; Canada; Feb. 22) - A once-dead deal between TransCanada and Western Canadian natural gas producers for lower-cost pipeline transport to key Ontario, Quebec and U.S. markets has new life. TransCanada said that following weeks of discussions with producers, it has launched a new open season — a period to determine market interest — on a long-term, fixed-price proposal to flow gas along its Canadian Mainline pipeline system from Alberta to the Dawn hub in Southern Ontario.
TransCanada had previously ended talks on the Mainline last November, citing a lack of shipper interest. The pipeline company and producers had been unable to find agreement on pricing and long-term commitments. TransCanada wants long-term pledges on its underused Mainline pipeline system, especially if it is going to offer lower tariffs, while gas producers in British Columbia and Alberta need greater, competitively priced access to Central Canadian and U.S. markets.
In recent years, Canadian producers have seen prices drop and their market share in North America eroded due to booming U.S. shale supplies. They face more competition as new pipelines in the U.S. move gas from the prolific and low-cost Marcellus and Utica basins to key eastern markets. Current prices are not high enough to justify the cost of moving Canadian gas without a pipeline deal, said Calgary consultant Bill Gwozd. The open season closes March 9; the targeted in-service date is November.
BP may invest to upgrade 200 of its wind turbines in U.S.
(Bloomberg; Feb. 16) - BP is weighing plans to update as many as 200 of its U.S. wind turbines with newer, higher-capacity equipment, a move that would represent the company’s biggest investment in renewable energy since its last wind farm came online in 2012. If the company greenlights the project — a decision that could be reached by mid-year — it would represent about 400 megawatts of additional capacity.
Laura Folse, chief executive of BP Wind Energy, said the move would allow the company to capitalize on production tax credits while optimizing operations at farms in Texas and Kansas. The company put down an initial investment in December 2016 in order to qualify for the full tax credit of 2.3 cents per kilowatt hour, which started scaling down this year. The updates involve swapping out aging equipment such as gearboxes, drive trains and blades, while keeping towers and foundations. BP said the upgraded technology would improve efficiency and reliability while increasing energy output.
With 14 wind farms — including one operated by another company in Hawaii — BP said it has the largest wind-energy business of all major oil companies. An example of the possible upgrades is the Silver Star Wind Farm near Dallas, where BP has determined the improvements could make its turbines more competitive against gas-fired power. That’s especially important in Texas, where BP doesn’t have long-term contracts to sell wind energy and must compete with the daily vagaries in the power markets.